VH Reservoir Mapping with Synchronous Data

ABSTRACT

A method and system of detecting and mapping a subsurface hydrocarbon reservoir includes determining ratio data for a plurality of orthogonal spectral components of naturally occurring low frequency background seismic data. The ratio data may be compared, plotted, contoured and displayed as a subsurface hydrocarbon reservoir map or a hydrocarbon potential map. The ratio data may represent a vertical spectral component of the seismic data over a horizontal spectral component of the seismic data. The subsurface hydrocarbon reservoir map may include contouring the ratio data over a geographical area associated with the seismic data.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation of pending U.S. Utility applicationSer. No. 12/710,805 filed Feb. 23, 2010, which is a continuation of U.S.Utility application Ser. No. 11/757,362 filed 2 Jun. 2007, now U.S. Pat.No. 7,676,326 issued 9 Mar. 2010 hereby incorporated by reference in itsentirety, which claim the benefit of expired U.S. ProvisionalApplication No. 60/804,420 filed 9 Jun. 2006, and expired U.S.Provisional Application No. 60/806,455 filed 30 Jun. 2006.

BACKGROUND OF THE DISCLOSURE

1. Technical Field

The disclosure is related to seismic exploration for oil and gas, andmore particularly to processing and displaying seismic data.

2. Description of the Related Art

Seismic exploration for hydrocarbons generally is conducted using asource of seismic energy and receiving and recording the energygenerated by the source using seismic detectors. On land, the seismicenergy source may be an explosive charge or another energy source havingthe capacity to impart impacts or mechanical vibrations at or near theearth's surface. Seismic waves generated by these sources travel intothe earth subsurface and are reflected back from boundaries and reachthe surface of the earth at varying intervals of time depending on thedistance traveled and the characteristics of the subsurface materialtraversed. The return waves are detected by the sensors andrepresentations of the seismic waves as representative electricalsignals are recorded for processing.

Normally, signals from sensors located at varying distances from thesource are combined together during processing to produce “stacked”seismic traces. In marine seismic surveys, the source of seismic energyis typically air guns. Marine seismic surveys typically employ aplurality of sources and/or a plurality of streamer cables, in whichseismic sensors are mounted, to gather three dimensional data.

The process of exploring for and exploiting subsurface hydrocarbonreservoirs is often costly and inefficient because operators haveimperfect information from geophysical and geological characteristicsabout reservoir locations. Furthermore, a reservoir's characteristicsmay change as it is produced.

Data acquisition for oil exploration may have a negative impact on theenvironment. The impact of oil exploration methods on the environmentmay be reduced by using low-impact methods and/or by narrowing the scopeof methods requiring an active source, including reflection seismic andelectromagnetic surveying methods.

Geophysical and geological methods are used to determine well locations.Expensive exploration investment is often focused in the most promisingareas using relatively slow methods, such as reflection seismic dataacquisition and processing. The acquired data are used for mappingpotential hydrocarbon-bearing areas within a survey area to optimizeexploratory well locations and to minimize costly non-productive wells.

The time from mineral discovery to production may be shortened if thetotal time required to evaluate and explore a survey area can be reducedby applying selected methods alone or in combination with othergeophysical methods. Some methods may be used as a standalone decisiontool for oil and gas development decisions when no other data isavailable. Preferable methods will be economical, have a lowenvironmental impact, and relatively efficient with rapid dataacquisition and processing.

Geophysical and geological methods are used to maximize production afterreservoir discovery as well. Reservoirs are analyzed using time lapsesurveys (i.e. repeat applications of geophysical methods over time) tounderstand reservoir changes during production.

SUMMARY

In one embodiment a method of locating subsurface hydrocarbon reservoirsor displaying hydrocarbon potential maps includes acquiring seismic datahaving a plurality of components, dividing the seismic data into timewindows, applying a data transform to the seismic data having aplurality of components to obtain transformed data components,determining a ratio of the transformed data components and recording theratio of the transformed data components in a form for display.

In another embodiment a computerized method for determining a subsurfacehydrocarbon reservoir location includes determining the subsurfacehydrocarbon reservoir location based on ratio data from a plurality oforthogonal spectral components of naturally occurring low frequencybackground seismic data. The ratio data that exceed a predeterminedthreshold value, which may be in a predetermined frequency range,indicate the presence of subsurface hydrocarbons.

In another embodiment a computerized method of mapping a subsurfacehydrocarbon reservoir includes selecting ratio data which exceed apredetermined threshold value for map locations indicating a subsurfacehydrocarbon reservoir. The ratio data are derived from a plurality oforthogonal spectral components of naturally occurring low frequencybackground seismic data.

In another embodiment an information handling system for determiningsubsurface hydrocarbons associated with an area of seismic dataacquisition includes a processor configured to determine whether a ratiocalculated from a plurality of orthogonal spectral components ofnaturally occurring low frequency background seismic data exceeds apredetermined threshold value, in predetermined frequency range, whereinthe ratio exceeding the threshold value indicates a presence ofsubsurface hydrocarbons. The information handling system also includes acomputer readable medium for storing the determined ratio indicating thepresence of subsurface hydrocarbons.

In another embodiment a system for subsurface hydrocarbon reservoirmapping includes a machine readable medium storing naturally occurringlow frequency background seismic data and map values associated with theseismic data. A processor is configured to determine a plurality of mapvalues associated with the seismic data, each map value determined froma ratio of a vertical spectral component to at least one horizontalspectral component of the seismic data. The processor is configured todetermine map values greater than a predetermined threshold thatindicate the presence of subsurface hydrocarbons.

In another embodiment a set of application program interfaces isembodied on a machine readable medium for execution by a processor inconjunction with an application program for detecting a subsurfacehydrocarbon reservoir. The set of application program interfacesincludes a first interface that receives ratio data representative of avertical spectral component relative to a horizontal spectral component,the spectral components derived from naturally occurring low frequencybackground seismic data. A second interface receives the ratio data forcomparison with a predetermined threshold value to determine whether theratio data indicates the presence of a subsurface hydrocarbon reservoir.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic illustration of a method according to anembodiment of the present disclosure for calculating a spectral ratio;

FIG. 2 illustrates a flow chart related to a method for processingaccording to an embodiment of the present disclosure for determiningparameters related to subsurface hydrocarbon reservoir detection; and

FIG. 3 is diagrammatic representation of a machine in the form of acomputer system within which a set of instructions, when executed maycause the machine to perform any one or more of the methods andprocesses described herein.

DETAILED DESCRIPTION

Information to enable the direct detection of hydrocarbon reservoirs orforming hydrocarbon potential maps or displays may be extracted fromnaturally occurring seismic waves and vibrations measured at the earth'ssurface. These naturally occurring waves may be measured using passiveseismic data acquisition methods to acquire naturally occurringbackground seismic data. Peaks or troughs in the spectral ratio betweenthe vertical and the horizontal components of the background waves maybe used as an indicator for the presence of hydrocarbon reservoirs.While references is made to hydrocarbon reservoir maps, it should beunderstood that the methods apply equally to methods for hydrocarbonpotential maps, that is where data indicated the possibility ofhydrocarbons in the subsurface.

Low-impact survey methods like passive seismic data acquisition may beused for reconnaissance in frontier exploration areas, to monitorreservoirs over the productive life of a field or to cost-effectivelyupgrade data room information to generate higher license bids. Specificapplications for passive seismic data include monitoring fluid flow,estimating shear-wave velocities, site zonation and shear-waveamplification studies for earthquake hazard surveys, monitoringhydraulic fracturing during reservoir stimulation and inversion forearth structure.

Passive seismic data acquisition methods rely on seismic energy fromsources not directly associated with the data acquisition. In passiveseismic monitoring there is no actively controlled and triggered source.Examples of low frequency ambient waves that may be recorded withpassive seismic acquisition are microseisms (e.g., rhythmically andpersistently recurring low-frequency earth tremors), microtremors andother anthropogenic or localized seismic energy sources.

Microtremors are attributed to the background energy present in theearth that may be due to non-seismic sources or anthropogenic noise.Microtremor seismic waves may include sustained seismic signals within alimited frequency range. Microtremor signals, like all seismic waves,contain information affecting spectral signature characteristics due tothe media or environment that the seismic waves traverse. Thesenaturally occurring relatively low frequency background seismic waves(sometimes termed noise or hum) of the earth may be generated from avariety sources, some of which may be indeterminate.

Survey results from passive seismic surveying demonstrate that thespectral characteristics of microtremor seismic waves often containrelevant information for direct hydrocarbon detection. Directhydrocarbon reservoir indicators may be extracted from naturallyoccurring low frequency background seismic data using spectral analysisof these microtremors. Spectral ratios or changes in spectral ratiosover geographic areas may be used to delineate subsurface hydrocarbonreservoirs. Microtremor analysis provides a method for identificationand mapping of fluid reservoirs or reservoir related parameters directlyfrom data acquired near the earth's surface in land and marine areasusing naturally occurring seismic background waves. Collected over timethese data highlight changes in reservoir parameters.

Microtremor analysis allows for direct determination of a hydrocarbonreservoir independent of the reservoir structure. Additionally, thethickness of strata associated with a hydrocarbon reservoir may bedetermined or inferred from microtremor analysis.

One or more sensors are used to measure vertical and horizontalcomponents of motion due to background seismic waves at multiplelocations within a survey area. These components may be measuredseparately or in combination and may be recorded as signals representingdisplacement, velocity, and/or acceleration.

The sensors may measure the components of motion simultaneously orasynchronously. As the spectral ratio of the acquired signal for anylocation may be quite stable over time, the components of motion may notneed to be measured simultaneously. This may be especially applicable inareas with relatively low local ambient wave energy and for dataacquired over relatively short time periods (e.g., a few weeks).Spectral ratios determined from asynchronous components at a locationmay be used as it is the relative difference of spectral components asopposed to specific contemporaneous differences that may be indicativeof reservoir characteristics. However, due to anthropogenic or localizedseismic energy generated in the vicinity of the seismic survey notrelated to subsurface reservoirs, relative quiescent periods free ofthis local anthropogenic seismic energy wherein orthogonal datacomponents are substantially contemporaneously acquired may providebetter quality data for delineating subsurface characteristics.

The spectral ratio of vertical to horizontal data components may becalculated to obtain a ratio of at least one horizontal component overthe vertical component (a H/V ratio), or the vertical component over atleast one horizontal component (a V/H spectral ratio). Characteristicsof spectral ratio data may be mapped, for example by plottinggeographically and contouring the values. Peaks (or troughs)representative of anomalies within the spectral ratio map may correspondto hydrocarbon or other fluid accumulation within the earth. Changes inV/H ratios over a survey area may be used to detect the boundaries ofthe reservoirs, and may correspond to areal boundaries of hydrocarbonaccumulations. These anomalies may also give an indication of thethickness of fluid reservoirs. This information may be compared,analyzed and integrated with other geophysical and geological knowledgeto improve an operator's understanding of the subsurface.

Geophysical survey local conditions may affect a method's results. Inmany cases the spectral ratio method provides a reliable directhydrocarbon indicator; in other cases a skilled operator can use theresults to improve their interpretation of other geological andgeophysical data and generate an improved subsurface model allowing formore efficient exploration and production decisions.

The sensor equipment for measuring seismic waves may be any type ofseismometer. Seismometer equipment having a large dynamic range andenhanced sensitivity compared with other transducers may provide thebest results (e.g., multicomponent earthquake seismometers). A number ofcommercially available sensors utilizing different technologies may beused, e.g. a balanced force feed-back instrument or an electrochemicalsensor. An instrument with high sensitivity at very low frequencies andgood coupling with the earth enhances the efficacy of the method.

Ambient noise conditions representative of seismic wave energy that mayhave not traversed subsurface reservoirs can negatively affect therecorded data. Techniques for removing unwanted artifacts and artificialsignals from the data, such as cultural and industrial noise, areimportant for applying this method successfully in areas where there ishigh ambient noise that has not interacted with a subsurface hydrocarbonreservoir.

The spectral ratio method has several advantages over conventionalseismic data acquisition for exploration including that the techniquedoes not require an artificial seismic source, such as an explosion,mechanically generated vibration or electric current. Additionally, theresults from spectral analysis are repeatable and the results may becorrelated to hydrocarbon accumulations. There is little or noenvironmental impact due to data acquisition. The method is applicablefor land, transition zones and marine areas. The method has applicationin areas where higher frequencies are greatly affected by geologicalconditions, e.g. in areas where soft soil layers attenuatehigh-frequency seismic signals as well as areas where salt formations orvolcanic bodies (e.g. basalt flows, volcanic sills) scatter or obscurehigher frequencies.

Spectral ratio analysis may take advantage of the selective absorptionand hydrocarbon induced relative amplification of relativelylow-frequency seismic background waves to enable mapping spectraldifference that directly indicate hydrocarbon reservoirs.

The spectral ratio of the horizontal over the vertical components (H/Vratio) of seismic background waves has been used as an indicator forsoft soil layers and other near-surface structures. Soft soil resonanceeffects visible in H/V spectra often occur at frequencies (up to 20 Hz).In contrast to the soft soil effect, in the vicinity of hydrocarbonreservoirs, the horizontal earth movements may be attenuated morestrongly than the vertical movements as compared to areas distal fromhydrocarbon reservoirs. This relative attenuation may result in a troughin the H/V ratio spectrum or a peak in the V/H ratio spectrum. Thehydrocarbon related peak in the V/H spectrum may be located atrelatively low frequencies (e.g., between 0 and 10 Hz, and often in therange 1 to 4 Hz), though parameters may be case specific.

FIG. 1 is a schematic illustration of a method according to anembodiment of the present disclosure using passively acquired naturallyoccurring background seismic data to determine a spectral ratio relatedto direct indications of hydrocarbons. The embodiment, which may includeone or more of the following referenced components (in any order), is amethod of locating subsurface anomalies related to hydrocarbonaccumulations that includes obtaining seismic data having a plurality ofcomponents 101. The acquired data may be time stamped and includemultiple data vectors. An example is multicomponent earthquake typeseismometry data, which includes recordings of low-frequency seismicbackground waves as differentiated from localized or anthropogenicenergy related seismicity. The multiple data vectors may each beassociated with an orthogonal direction of movement. Data may beacquired in, or mathematically rotated into, orthogonal componentvectors arbitrarily designated east, north and depth (respectively, Ve,Vn and Vz) or designated V_(x), V_(y) and V_(z) according to desiredconvention. The data vectors may all be the same length andsynchronized.

The vector data may be divided into time windows 103 for processing.Window lengths may be greater than ten times the period of the lowestfrequency of interest. For example if a frequency of interest has aperiod around 7 seconds all the windows may be at least 70 seconds long.However, the length of time windows for analysis may be chosen toaccommodate processing or operational concerns.

A data transform may be applied to each component of the vector data105. Seismic data frequency content often varies with time.Time-frequency decomposition (spectral decomposition) of a seismicsignal enables analysis and characterization of the signaltime-dependent frequency response due to subsurface materials andreservoir parameters.

Various data transformations are useful for time-frequency analysis ofseismic signals, such as continuous or discrete Fourier or wavelettransforms. Examples include without limitation the classic Fouriertransform or one of the many continuous Wavelet transforms (CWT) ordiscrete wavelet transforms. Examples of other transforms include Haartransforms, Haademard transforms and wavelet transforms. The Morletwavelet is an example of a wavelet transform that may be applied toseismic data. Wavelet transforms have the attractive property that thecorresponding expansion may be differentiable term by term when theseismic trace is smooth. Additionally, signal analysis, filtering, andsuppressing unwanted signal artifacts may be carried out efficientlyusing transforms applied to the acquired data signals.

One or more orthogonal components of the acquired data may be merged,for example the horizontal data components 107. Horizontal components Veand Vn may be merged by any of several ways including a root-mean-squareaverage so that horizontal component H may be defined as H=√{square rootover ((V_(e) ²+V_(n) ²)/2)}. Whether merging data components isundertaken before or after a data transform is applied to the data is amatter of choice.

Additionally the spectra may be smoothed using a moving average 109. Thesmoothing parameter defines the width of the window (in Hz) used forcalculating moving averages. A large smoothing parameter leads to strongsmoothing and a small smoothing parameter leads to less smoothing.Typical values may be between 0.1 Hz and 2 Hz, but will be casedependent. A smoothing parameter for a flow may be selected at thebeginning of a processing flow for application prior to calculating aspectral ratio.

The V/H spectral ratio is calculated 111 based on the spectral division(e.g., point-by-point spectral division) between the transformed outputof at least two orthogonal components, such as a horizontal spectralcomponent and the vertical spectral component. The horizontal componentmay be a combination of the measured horizontal components (as in 107).These spectra or the calculated spectral ratios may be averaged overtime windows 113. Averaging over time windows may be by arithmetic meanor geometric mean. Averaging of spectra may be undertaken before orafter dividing the spectra into spectral ratios. The results after thisprocessing may be output 115 in a form for mapping or other display.Maps of this V/H spectral ratio output may provide direct indications ofthe geographical extent of hydrocarbon reservoirs in the field surveyvicinity. Values indicating the presence of a hydrocarbon reservoir maybe selecting using a threshold ratio value which may be determinedobjectively or subjectively. For example, ratio data that exceed (beinggreater than) a threshold V/H ratio of 1.5 (or that exceed (lower than)an H/V ratio of 0.67) has been shown to indicate a hydrocarbonreservoir. Greater or lower threshold values may be area or surveydependent. An example of ratio data exceeding a predetermined thresholdvalue indicating the presence of subsurface hydrocarbons over a surveyarea includes a non-random grouping of V/H ratio data greater then 1.0.Alternatively the V/H ratio may be chosen greater than 1.1, 1.2 etc.

FIG. 2 illustrates an embodiment, which may include one or more of thereferenced components (in any order), for determining hydrocarbonaccumulations in a subsurface reservoir. Seismic data that has aplurality of components 201 are obtained. The data may include a timestamp vector and orthogonal data vectors. The data vectors may be allsame length and synchronized. The components may be orthogonal vectordata representing two horizontal directions and a vertical direction.

The multicomponent input data may be cleaned to remove transients 203.One way to remove transients is to process data when transients are notpresent. Signal filtering 205 with the time domain data includefrequency filtering and bias removal. The data may be detrended so thatone or more linear trends are removed. The data may be band passfiltered or a DC offset bias removed as well.

The data may be divided into time windows 207. The time window lengthfor data vectors may be chosen based on operational or processingconsiderations, and an example length may correspond to 10 cycles of thelower frequency range of interest. Horizontal data components may bemerged, for example by averaging or by a root-mean-square weighting ofthe values.

Data may be rotated to any desired reference frame. A reference framewhere the vertical vector direction is normal to the geoid may bebeneficial for subsequent formation of V/H spectral ratios. The spectramay be smoothed, for example with a moving average function. The datamay be decomposed into spectral components 209 by any time-frequencydecomposition, e.g., Fourier or Wavelet transform.

One or more orthogonal components of the obtained data may be merged211, for example the horizontal data components (e.g., 107). Horizontalcomponents Ve and Vn may be merged by any of several ways including ageometrical means like the root-mean-square average so that horizontalcomponent H may be defined as H=√{square root over ((V_(e) ²+V_(n)²)/2)}. Other methods for merging including using an arithmetic mean, aPythagorean mean or a complex Fourier transformation.

The spectra may be smoothed 213 using a low pass filter, a moving windowwith a fixed bandwidth or a variable bandwidth. The spectra may beaveraged 215 using an arithmetic mean or a geometric mean.

A spectral ratio is determined between transformed components 217. Thespectral ratio may be determined with point-by-point spectral division,for example determining spectral ratios between horizontal and verticaldata. A V/H spectral ratio may be determined using the verticalcomponent with one or both horizontal components, or a merged version ofthe horizontal components. The spectral ratio may be averaged 219 aswell, using an arithmetic or geometric mean. The calculated ratio may bestored 221 (to a computer readable media) in a form for display and/orformed into a map. A map created with the calculated ratio may give adirect indication of the geographical extent of subsurface hydrocarbonreservoirs.

In an alternative embodiment, passively acquired seismic data as inputare examined as to whether vector components have the same length, thedata are divided into time windows, a Fast Fourier Transform (FFT) orother transform is applied to each component, horizontal components aremerged to obtain one horizontal component, the data are be smoothed, aV/H spectral ratio is calculated and the spectra are averaged overdiscrete time ranges within time windows. Data output may include afrequency stamp vector and one vector with the corresponding V/Hspectrum amplitudes. A frequency stamp vector contains the discretevalues of frequency where there is a corresponding amplitude valueavailable (e.g. from the Fourier transformation). The amplitude spectrumof a signal may be plotted against the frequency stamp vector to obtaina display of the spectrum as a curve. The frequency vector covers thefrequency range of interest (e.g. from 0 to 20 Hz) by equally spacedvalues. Example: 0, 0.1, 0.2, 0.3, . . . , 19.9, 20 (values in Hz).

While data may be acquired with multi-component earthquake seismometerequipment with large dynamic range and enhanced sensitivity, manydifferent types of sensor instruments can be used with differentunderlying technologies and varying sensitivities. Sensor positioningduring recording may vary, e.g. sensors may be positioned on the ground,below the surface or in a borehole. The sensor may be positioned on atripod or rock pad. Sensors may be enclosed in a protective housing forocean bottom placement. Wherever sensors are positioned, good couplingresults in better data. Recording time may vary, e.g. from minutes tohours or days. In general terms, longer-term measurements may be helpfulin areas where there is high ambient noise (representative of waveenergy not traversing a subsurface hydrocarbon reservoir) and provideextended periods of data with fewer noise problems.

The layout of a survey may be varied, e.g. measurement locations may beclose together or spaced widely apart and different locations may beoccupied for acquiring measurements consecutively or simultaneously.Simultaneous recording of a plurality of locations may provide forrelative consistency in environmental conditions that may be helpful inameliorating problematic or localized ambient noise not related tosubsurface characteristics.

FIG. 3 illustrates a schematic example of the hardware and operatingenvironment for which embodiments as described herein and theirequivalents may be practiced. The description of FIG. 3 includes ageneral description of computer hardware, computing environment orinformation handling system for which the embodiments may beimplemented. Although specific hardware may not be required, embodimentsmay be implemented in the general context of computer-executableinstructions, such as program modules, being executed by a computer.Various embodiments may be practiced with a personal computer, amainframe computer or combinations that include workstations withservers. Program modules include routines, programs, objects, componentsand data structures for performing tasks, processing data, and recordingand displaying information.

The products as defined herein may be particularly adapted for use inwhat are termed “information handling system.” An information handlingsystem is any instrumentality or aggregate of instrumentalitiesprimarily designed to compute, classify, process, transmit, receive,retrieve, originate, switch, store, display, manifest, measure, detect,record, reproduce, handle or utilize any form of information,intelligence or data for business, scientific, control or otherpurposes. Examples include personal computers and larger processors suchas servers, mainframes, etc, and may contain elements illustrated inFIG. 3.

Embodiments may be practiced with various computer or informationhandling system configurations that separately or in combination mayinclude hand-held devices, multiprocessor systems, microprocessor-basedor programmable consumer electronics, network computers, minicomputers,mainframe computers, and the like. Embodiments may be practiced withtasks performed in and over distributed computing environments thatinclude remote processing devices linked through a communicationsnetwork. Program modules operating in distributed computing environmentsmay be located in various memory locations, both local and remote.

FIG. 3 is illustrative of hardware and an operating environment forimplementing a general purpose computing device or information handlingsystem in the form of a computer 10. Computer 10 includes a processor orprocessing unit 11 that may include ‘onboard’ instructions 12. Computer10 has a system memory 20 attached to a system bus 40 that operativelycouples various system components including system memory 20 toprocessing unit 11. The system bus 40 may be any of several types of busstructures using any of a variety of bus architectures as are known inthe art.

While one processing unit 11 is illustrated in FIG. 3, there may be asingle central-processing unit (CPU) or a graphics processing unit(GPU), or both or a plurality of processing units. Computer 10 may be astandalone computer, a distributed computer, or any other type ofcomputer.

System memory 20 includes read only memory (ROM) 21 with a basicinput/output system (BIOS) 22 containing the basic routines that help totransfer information between elements within the computer 10, such asduring start-up. System memory 20 of computer 10 further includes randomaccess memory (RAM) 23 that may include an operating system (OS) 24, anapplication program 25 and data 26.

Computer 10 may include a disk drive 30 to enable reading from andwriting to an associated computer or machine readable medium 31.Computer readable media 31 includes application programs 32 and programdata 33.

For example, computer readable medium 31 may include programs to processseismic data, which may be stored as program data 33, according to themethods disclosed herein. The application program 32 associated with thecomputer readable medium 31 includes at least one application interfacefor receiving and/or processing program data 33. The program data 33 mayinclude seismic data acquired according to embodiments disclosed herein.At least one application interface may be associated with calculating aratio of data components, which may be spectral components, for locatingsubsurface hydrocarbon reservoirs.

The disk drive may be a hard disk drive for a hard drive (e.g., magneticdisk) or a drive for a magnetic disk drive for reading from or writingto a removable magnetic media, or an optical disk drive for reading fromor writing to a removable optical disk such as a CD ROM, DVD or otheroptical media.

Disk drive 30, whether a hard disk drive, magnetic disk drive or opticaldisk drive is connected to the system bus 40 by a disk drive interface(not shown). The drive 30 and associated computer-readable media 31enable nonvolatile storage and retrieval for one or more applicationprograms 32 and data 33 that include computer-readable instructions,data structures, program modules and other data for the computer 10. Anytype of computer-readable media that can store data accessible by acomputer, including but not limited to cassettes, flash memory, digitalvideo disks in all formats, random access memories (RAMs), read onlymemories (ROMs), may be used in a computer 10 operating environment.

The application programs 32 may be associated with one or moreapplication program interfaces. An application programming interface(API) 35 may be an interface that a computer system, library orapplication provides in order to allow requests for services to be madeof it by other computer programs, and/or to allow data to be exchangedbetween them. An API 35 may also be a formalized set of software callsand routines that can be referenced by an application program 32 inorder to access supporting application programs or services, whichprograms may be accessed over a network 90.

APIs 35 are provided that allow for higher level programming fordisplaying and mapping subsurface reservoirs. For example, APIs areprovided for receiving seismic data, and decomposing, merging, smoothingand averaging the data. Moreover, the APIs allow for receiving thefrequency product data and storing it for display.

Data input and output devices may be connected to the processing unit 11through a serial interface 50 that is coupled to the system bus. Serialinterface 50 may a universal serial bus (USB). A user may enter commandsor data into computer 10 through input devices connected to serialinterface 50 such as a keyboard 53 and pointing device (mouse) 52. Otherperipheral input/output devices 54 may include without limitation amicrophone, joystick, game pad, satellite dish, scanner or fax,speakers, wireless transducer, etc. Other interfaces (not shown) thatmay be connected to bus 40 to enable input/output to computer 10 includea parallel port or a game port. Computers often include other peripheralinput/output devices 54 that may be connected with serial interface 50such as a machine readable media 55 (e.g., a memory stick), a printer 56and a data sensor 57. A seismic sensor or seismometer for practicingembodiments disclosed herein are nonlimiting examples of data sensor 57.A video display 72 (e.g., a liquid crystal display (LCD), a flat panel,a solid state display, or a cathode ray tube (CRT)) or other type ofoutput display device may also be connected to the system bus 40 via aninterface, such as a video adapter 70. A map display created fromspectral ratio values as disclosed herein may be displayed with videodisplay 72.

A computer 10 may operate in a networked environment using logicalconnections to one or more remote computers. These logical connectionsare achieved by a communication device associated with computer 10. Aremote computer may be another computer, a server, a router, a networkcomputer, a workstation, a client, a peer device or other common networknode, and typically includes many or all of the elements describedrelative to computer 10. The logical connections depicted in FIG. 3include a local-area network (LAN) or a wide-area network (WAN) 90.However, the designation of such networking environments, whether LAN orWAN, is often arbitrary as the functionalities may be substantiallysimilar. These networks are common in offices, enterprise-wide computernetworks, intranets and the Internet.

When used in a networking environment, the computer 10 may be connectedto a network 90 through a network interface or adapter 60. Alternativelycomputer 10 may include a modem 51 or any other type of communicationsdevice for establishing communications over the network 90, such as theInternet. Modem 51, which may be internal or external, may be connectedto the system bus 40 via the serial interface 50.

In a networked deployment computer 10 may operate in the capacity of aserver or a client user machine in server-client user networkenvironment, or as a peer machine in a peer-to-peer (or distributed)network environment. In a networked environment, program modulesassociated with computer 10, or portions thereof, may be stored in aremote memory storage device. The network connections schematicallyillustrated are for example only and other communications devices forestablishing a communications link between computers may be used.

In one embodiment a computerized method for determining a subsurfacehydrocarbon reservoir location includes determining the subsurfacehydrocarbon reservoir location based on ratio data from a plurality oforthogonal spectral components of naturally occurring low frequencybackground seismic data. The ratio data that exceed a predeterminedthreshold value indicate the presence of subsurface hydrocarbons.

The method may include calculating ratio data are from vertical spectralcomponents of the seismic data relative to horizontal spectralcomponents of the seismic data. The ratio data may be calculated withvertical spectral components as a numerator and with horizontal spectralcomponents as a denominator. With vertical spectra to horizontalspectra, the presence of subsurface hydrocarbons may be indicated withratio values greater than a predetermined threshold value of 1.5 though,of course, the threshold that indicates hydrocarbon presence will becase dependent. For example, in some areas, the predetermined thresholdmay be selected with a value of 1.0. Conversely, with a horizontalspectral component as a numerator and with a vertical spectral componentof as a denominator, the ratio data associated with the presence ofsubsurface hydrocarbons may be less than a predetermined threshold valueof 0.67. The ratio data may be selected for a frequency range between 1Hz and 5 Hz. The orthogonal spectral components may be determined byapplying a data transform to a plurality of orthogonal components ofmotion for the naturally occurring low frequency background seismicdata. The data transform to apply may be a discrete Fourier transform, acontinuous Fourier transform, a continuous wavelet transform, or adiscrete wavelet transform.

In another embodiment a computerized method of mapping a subsurfacehydrocarbon reservoir includes selecting ratio data which exceed apredetermined threshold value for map locations indicating a subsurfacehydrocarbon reservoir. The ratio data are derived from a plurality oforthogonal spectral components of naturally occurring low frequencybackground seismic data.

The method may include determining ratio data representing a verticalspectral component of the seismic data over a horizontal spectralcomponent of the seismic data. A subsurface hydrocarbon reservoir mapmay be created by contouring the ratio data over a geographical areaassociated with the seismic data. The orthogonal spectral components maybe determined by applying a data transform to a plurality of orthogonalcomponents of motion for the naturally occurring low frequencybackground seismic data. The data transform may be a discrete Fouriertransform, a continuous Fourier transform, a continuous wavelettransform, or a discrete wavelet transform.

In another embodiment an information handling system for determiningsubsurface hydrocarbons associated with an area of seismic dataacquisition includes a processor configured to determine whether a ratiocalculated from a plurality of orthogonal spectral components ofnaturally occurring low frequency background seismic data exceeds apredetermined threshold value wherein the ratio exceeding the thresholdvalue indicates a presence of subsurface hydrocarbons. The informationhandling system also includes a computer readable medium for storing thedetermined ratio indicating the presence of subsurface hydrocarbons.

The processor of the information handling system may be configured toapply a data transform to the naturally occurring low frequencybackground seismic data to obtain a vertical spectral component and toobtain at least one horizontal spectral component. Additionally,horizontal spectral components may be merged into one horizontalspectral component. The predetermined threshold value for the ratioindicative of subsurface hydrocarbons may be equal to or greater than1.5 or some other value derived from experience locally or from otherareas. The ratio may be determined for vertical spectral componentfrequencies and horizontal spectral component frequencies between 1 Hzand 5 Hz. The information handling system may also include a graphicaldisplay coupled to the processor and configured to present a view of theratio as a function of position. The processor may be configured togenerate the view (as a map) by contouring the ratio over an areaassociated with the seismic data.

In another embodiment a system for subsurface hydrocarbon reservoirmapping includes a machine readable medium storing naturally occurringlow frequency background seismic data and map values associated with theseismic data. A processor is configured to determine a plurality of mapvalues associated with the seismic data, each map value determined froma ratio of a vertical spectral component to at least one horizontalspectral component of the seismic data. The processor is configured todetermine map values greater than a predetermined threshold thatindicate the presence of subsurface hydrocarbons.

The processor for the system may be configured to apply a data transformto naturally occurring low frequency background seismic data to obtain avertical spectral component and to obtain at least one horizontalspectral component. Additionally, horizontal components may be merged.The processor may also be configured to contour the ratio over ageographical area associated with the seismic data to create values fora map of a subsurface hydrocarbon reservoir. A graphical display coupledto the processor may be configured to present a view of the ratio as afunction of position, wherein the processor is configured to generatethe view by contouring the ratio data. The processor may alsodifferentiate map values indicating the presence of subsurfacehydrocarbons from other map values for the view displayed.

In another embodiment a set of application program interfaces isembodied on a machine readable medium for execution by a processor inconjunction with an application program for detecting a subsurfacehydrocarbon reservoir. The set of application program interfacesincludes a first interface that receives ratio data representative of avertical spectral component relative to a horizontal spectral component,the spectral components derived from naturally occurring low frequencybackground seismic data. A second interface receives the ratio data forcomparison with a predetermined threshold value to determine whether theratio data indicates the presence of a subsurface hydrocarbon reservoir.

A third interface may receive vertical motion component data fromnaturally occurring low frequency background seismic data for a datatransform to obtain a vertical spectral component and a fourth interfacemay receive horizontal motion component data from the seismic data toobtain a horizontal spectral component. The data transform for the thirdand fourth interface may be a discrete Fourier transform, a continuousFourier transform, a continuous wavelet transform, or a discrete wavelettransform. A fifth interface may receive data to merge two horizontalspectral components to obtain a merged horizontal spectral component. Asixth interface may receive the ratio data in a form for display. Aseventh interface may receive the ratio data for contouring in a formfor display as a map.

In another embodiment a method of mapping a subsurface hydrocarbonreservoir includes determining a ratio data for a plurality oforthogonal spectral components of naturally occurring low frequencybackground seismic data. The ratio data are displayed as a subsurfacehydrocarbon reservoir map.

The ratio data may represent a vertical spectral component of theseismic data over a horizontal spectral component of the seismic data.The subsurface hydrocarbon reservoir map may include contouring theratio data over a geographical area associated with the seismic data.The orthogonal spectral components may be determined by applying a datatransform to a plurality of orthogonal components of motion for thenaturally occurring low frequency background seismic data. The datatransform may be selected from the group consisting of a discreteFourier transform, a continuous Fourier transform, a continuous wavelettransform, and a discrete wavelet transform. The two horizontal spectralcomponents may be merged to obtain a horizontal spectral component.Merging the two horizontal spectral components may include determiningthe square root of the sum of the squares of the two horizontal spectralcomponents. Processing the plurality of orthogonal spectral componentsmay include smoothing the data with a low pass filter, smoothing thedata with a fixed bandwidth moving window, smoothing the data with avariable bandwidth moving window, averaging the data with an arithmeticmean, and averaging the data with a geometrical mean.

In another embodiment a set of application program interfaces isembodied on a machine readable medium for execution by a processor inconjunction with an application program for determining a spectral ratiofrom naturally occurring low frequency background seismic data to map asubsurface hydrocarbon reservoir. The set of application programinterfaces includes a first interface that receives seismic data forcalculating ratio data of a vertical spectral component to a horizontalspectral component and a second interface that sends the ratio data to amachine readable media to store data associated with subsurfacehydrocarbon reservoir maps.

In another embodiment a method of locating subsurface hydrocarbonreservoirs includes acquiring seismic data having a plurality ofcomponents, dividing the seismic data into time windows, applying a datatransform to the seismic data having a plurality of components to obtaintransformed data components, determining a ratio of the transformed datacomponents and recording the ratio of the transformed data components ina form for display or mapping a subsurface hydrocarbon reservoir.

While various embodiments have been shown and described, variousmodifications and substitutions may be made thereto without departingfrom the spirit and scope of the disclosure herein. Accordingly, it isto be understood that the present embodiments have been described by wayof illustration and not limitation.

1-30. (canceled)
 31. A set of application program interfaces embodied ona machine readable medium for execution by a processor in conjunctionwith an application program for detecting a subsurface hydrocarbonreservoir, the set of application program interfaces comprising: a firstinterface that receives ratio data acquired with a plurality ofsimultaneously recording sensors, representative of a vertical spectralcomponent relative to a horizontal spectral component, the spectralcomponents derived from ambient seismic data; and a second interfacethat receives the ratio data to compare with a predetermined thresholdvalue, wherein ratio data exceeding the threshold value indicates thelocation of a subsurface hydrocarbon reservoir.
 32. The set ofapplication interface programs according to claim 1 further comprising:a third interface that receives vertical motion component data fromambient seismic data for a data transform to obtain a vertical spectralcomponent; and a fourth interface that receives horizontal motioncomponent data from naturally occurring low frequency background seismicdata for the data transform to obtain a horizontal spectral component.33. The set of application interface programs according to claim 1wherein the data transform for the third and fourth interface isselected from the group consisting of: a discrete Fourier transform, acontinuous Fourier transform, a continuous wavelet transform, and adiscrete wavelet transform.
 34. The set of application interfaceprograms according to claim 1 further comprising a fifth interface toreceive data to merge two horizontal spectral components to obtain amerged horizontal spectral component.
 35. The set of applicationinterface programs according to claim 1 further comprising a sixthinterface to receive the ratio data in a form for display.
 36. The setof application interface programs according to claim 1 furthercomprising a seventh interface to receive the ratio data for contouringin a form for display as a map.
 37. The set of application interfaceprograms according to claim 1 further comprising an eighth interface toreceive data from sensors positioned below ground in a borehole.
 38. Acomputerized method of mapping a subsurface hydrocarbon reservoircomprising: deriving a ratio data from a plurality of orthogonalspectral components of ambient seismic data acquired with a plurality ofsimultaneously recording; using a processing unit for determining ratiodata which exceed a predetermined threshold value indicative of asubsurface hydrocarbon reservoir to determine subsurface hydrocarbonreservoir map location positions; and storing the map location positionsin a form for display.
 39. The method of claim 8 further comprisingdetermining ratio data representing a vertical spectral component of theseismic data over a horizontal spectral component of the seismic data.40. The method of claim 8 further comprising creating a subsurfacehydrocarbon reservoir map by contouring the ratio data over ageographical area associated with the seismic data.
 41. The method ofclaim 8 wherein the orthogonal spectral components are determined by:applying a data transform to a plurality of orthogonal components ofmotion for the naturally occurring low frequency background seismicdata.
 42. The method of claim 11 wherein the data transform is selectedfrom the group consisting of: discrete Fourier transform, continuousFourier transform, continuous wavelet transform, and discrete wavelettransform.
 43. The method of claim 8 further comprising: processing theplurality of orthogonal spectral components by at least one selectedfrom the group of: smoothing with a low pass filter, smoothing with afixed bandwidth moving window, smoothing with a variable bandwidthmoving window, averaging with an arithmetic mean, and averaging with ageometrical mean.
 44. The method of claim 8 wherein the data areacquired with a plurality of simultaneously recording sensors positionedbelow ground in a borehole.
 45. An information handling system fordetermining the presence of subsurface hydrocarbons associated with anarea of seismic data acquisition comprising: a memory coupled to aprocessor, the memory for storing ambient seismic data acquired with aplurality of simultaneously recording sensors; a processor configured todetermine a ratio calculated from a plurality of orthogonal spectralcomponents of ambient seismic data; an application program configured todetermine when the ratio exceeds a predetermined threshold valueassociated with subsurface hydrocarbons; and a computer readable mediumfor storing the determined ratio.
 46. The information handling system ofclaim 15 wherein the memory coupled to the processor is configured tostore data acquired from sensors positioned below ground in a borehole.47. The information handling system of claim 15 wherein the processor isconfigured to apply a data transform to the naturally occurring lowfrequency background seismic data to obtain a vertical spectralcomponent and to obtain at least one horizontal spectral component. 48.The information handling system of claim 15 wherein the predeterminedthreshold value for the ratio is equal to or greater than 1.5.
 49. Theinformation handling system of claim 15 wherein the ratio is determinedfor vertical spectral component frequencies and horizontal spectralcomponent frequencies between 1 Hz and 5 Hz.
 50. The informationhandling system of claim 15 further comprising: a graphical displaycoupled to the processor and configured to present a view of the ratioas a function of position, wherein the processor is configured togenerate the view by contouring the ratio over an area associated withthe seismic data.